1. Field of the Invention
This invention relates to tools for oil wells, gas wells, and the like and more particularly to improved well packers.
2. Description of the Prior Art
A well packer, which is a device for blocking passage of fluids in an annular space between the well tubing and casing, may be used to protect well casing from high production or injection pressures, or from corrosive fluids, to prevent migration of fluids between zones through perforations or casing lengths, to isolate perforations and production in multiple completions, to increase flow efficiency, to maintain artificial lift control or to conserve energy in the reservoir by improved withdrawal rate control.
Most well packers have three main components: (1) a seal assembly for sealing the annular space, (2) a slip assembly for mounting and anchoring the packer in the well, and (3) a setting and release mechanism to apply and maintain, or relieve, the sealing force applied to the seal assembly. These components are often maintained in assembled relation by a mandrel.
An essential characteristic of the packer is that of reliability. Once a packer is installed, it should perform trouble-free for as long as desired. If the packer fails, the expense involved in retrieving and replacing the packer is usually quite high. Packer mechanics and the method by which a seal is maintained are major factors in determining overall packer cost and effectiveness.
Problems with prior art packers include excessive casing damage from slips, as well as slip failure. The slip assembly usually contains slip elements having teeth designed to penetrate into the casing wall and anchor the packer in position under pressure differentials which may exist across the packer. Theoretically, a packer can be seated and unseated a number of times without requiring the replacement of the slip elements. However, if longitudinal packer movement occurs as the slips are released, due to unequalized differential pressure across the packer or due to tubing tension or weight, damage to the casing may occur as well as dulling of the slip teeth. Movement may also result where the slips are corroded from an H.sub.2 S or other corrosive environment. The use of worn slips may cause a packer to fail in the well. Further, it is difficult to determine if the slip teeth are adequately sharp by visual inspection, since only a slight dulling can cause packer failure. Normally a packer should not be set at the same place in the casing where milling operations have taken place, or where slips have been engaged and held against a fairly high pressure differential. If damage to the casing has occurred when retrieving prior packers, it may be impossible to adequately seal the casing at the desired depth.
Methods for setting the slips and seal rings in packers include the application of an upward or downward force on a tubing string, actuation by hydraulic pressure, rotation of the tubing string, and use of a J-slot and pin arrangement. Problems transmitting the necessary torque to the packer are encountered with rotation methods. Hydraulic actuation has the problem of pressure fluctuation, with consequent repeated releasing and resetting of the slips into the casing, often resulting in casing damage, movement of the packer, and loss of sealing ability. With tension-type tools, problems may occur due to an inability to stretch the tubing sufficiently to effect normal release of the slips; in other cases where downward force must be applied, the packer may progressively move down to the plugback depth of the well while attempting to release the packer and slips, making it impossible to release the packer.
For greater packer reliability it is essential that the packer have a sealing element which will establish and maintain a seal under producing conditions. Most conventional packers are reliable in wells in normal-to-medium temperature ranges where hydrogen sulfide gas is not being produced. In deep, sour wells, however, hydrogen sulfide gas presents a highly corrosive environment, particularly at high pressures and temperatures, for packer operations and it is often difficult for conventional packers to sustain an effective seal under such conditions.
The packer sealing elements themselves are normally formed of an elastomeric material such as rubber. Typically, when a packer is set, the elastomer sealing element is compressed longitudinally and expanded radially to form a seal against the casing. During compression the elastomeric material tends to extrude between the packer body and the casing. After the packer has been set, retrieval is often difficult due to excessive extrusion of the sealing element. The seals cannot resume their approximate original configuration, which can cause the packer to become stuck, especially in deep wells. This problem is aggravated at high temperatures in such wells. Further, most elastomers, will not sustain an effective seal in a sour gas environment, particularly at high temperatures and pressures. Under these conditions, most elastomer seal rings become brittle, deteriorate or swell and lose sealing capability.
Several elastomeric and synthetic resin materials have been suggested to overcome the degradation effect caused by high temperatures in an H.sub.2 S environment. For example, polytetrafluroethylene, sold under the trade name Teflon, and certain fluoroelastomers have good temperature and chemical resistance. However, these materials, like most other elastomers and resins, have certain undesirable mechanical properties. One disadvantage is that under higher temperature conditions it is often difficult to prevent elastomeric and synthetic resin materials from being extruded from even very small clearances in the annular space. Another disadvantage is that some of the suggested seal materials such as Teflon have virtually no elasticity, and therefore are difficult to unseat and retrieve.